QEP Resources, Inc. (NYSE:QEP)
Q2 2016 Earnings Conference Call
July 28, 2016 09:00 AM ET
William Kent - Director, Investor Relations
Richard Doleshek - Executive Vice President and Chief Financial Officer
Charles Stanley - Chairman, President and Chief Executive Officer
David Heikkinen - Heikkinen Energy Advisors
Kevin Smith - Raymond James
Neal Dingmann - SunTrust Robinson Humphrey
Kashy Harrison - Simmons Piper Jaffray
Gabe Daoud - JPMorgan
David Tameron - Wells Fargo Securities
Brian Corales - Howard Weil Incorporated
Josh Silverstein - Deutsche Bank
Greetings and welcome to the QEP Resources Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. Please note that the call will be limited to one hour. And as a result, we may be unable to get to all the participants’ questions. [Operator Instructions] As a reminder, this conference is being recorded.
I would now like to turn the conference over to William Kent, Director of Investor Relations. Please go ahead.
Thank you, Barak and good morning and thank you for joining us for the QEP Resources second quarter 2016 results conference call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer; Richard Doleshek, Executive Vice President and Chief Financial Officer; and Jim Torgerson, Executive Vice President and Head of our E&P Business.
If you have not done so already, please go to our website, qepres.com to obtain copies of our earnings release, which contains tables with our financial results and a slide presentation with maps and other supporting materials. In today’s conference call, we will use a non-GAAP measure, EBITDA which is referred to as adjusted EBITDA in our earnings release and SEC filings and is reconciled to net income in the earnings release and SEC filings.
In addition, we will be making numerous forward-looking statements to remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which would be out of our control. We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks facing our business in our earnings release and SEC filings.
With that, I would like to turn the call over to Richard.
Thank you, Will and good morning everyone. As you all know, we had a pretty busy second quarter. On the A&D front, we signed a $600 million purchase and sale agreement that will increase our footprint in the core northern portion of the Midland Basin by about 50%. In conjunction with announcing the acquisition, we issued 23 million shares of common stock and raised $413 million in net proceeds. We also completed reorganization of the company in April that resulted in about a 6% reduction in headcount.
Turning to our results, in the second quarter of 2016, we generated $168.3 million of adjusted EBITDA compared to $115.1 million of adjusted EBITDA in the first quarter and $279.4 million in the second quarter of 2015. Production in the second quarter was 83.3 Bcfe or six-tenths of the Bcfe higher than the 82.7 Bcfe reported in the first quarter. Oil volumes were record 5.2 million barrels, up 33,000 barrels from the first quarter levels and NGL volumes were 1.5 million barrels, up 156,000 barrels from the first quarter.
Natural gas volumes were 42.9 Bcf, down 0.5 Bcf in the first quarter. Crude oil comprised 38% of our total production in the second quarter, which was about the same is in the first quarter. Given the anticipated timing of the closing of the Permian acquisition, we do not expect any meaningful contribution to production, LOE or G&A from the acquired property this year. In our updated guidance for 2016, only the capital expenditure range has been adjusted as a result of the transaction.
Our updated oil production guidance for 2016 is a range of 19.5 million to 20.5 million barrels, the midpoint of which is up 0.5 million barrels from our initiatives guidance midpoint. We increased our guidance for NGL production to 4.75 million to 5.25 million barrels, the midpoint of which his is up a 0.5 million barrels from initial guidance midpoint as well. Our guidance for natural gas production for 2016 is unchanged from the initial guidance that we provided in February.
QEP Energy’s net realized equivalent price, which includes the settlement of our commodity derivatives, averaged $4.31 per Mcfe, which was $0.63 per Mcfe or 17% higher than we realized in the fourth quarter of 2016 and $1.63 per Mcfe lower than we realized in the second quarter 2015. The weighted average field level equivalent price in the quarter was $3.72 per Mcfe, which was 27% higher than the first quarter.
Equivalent price reflects field level crude oil prices that were $39.88 per barrel, field level NGL prices that were $14.97 per barrel and field level natural gas prices that were $1.84 per Mcf. Field level crude oil revenues account for 67% of total field level revenues, which was about 8% higher than in the first quarter. Derivative settlements added $48.8 million or $0.59 per Mcfe to QEP Energy’s net price realizations compared to adding $0.75 per Mcfe in the first quarter.
Combined lease operating and transportation expenses were $123 million in the quarter down from $134 million in the first quarter, and $8 million lower than in the second quarter of 2016. Lower repair expenses saw order sales of cost and compression expenses were the drivers of the lower sequential LOE number.
On a per unit basis, lease operating expenses were $0.63 per Mcfe, which was down $0.10 per Mcfe in the first quarter and transportation expense was $0.83 per Mcfe, which was down $0.06 per Mcfe in the first quarter. Our guidance for lease operating and transportation expenses is unchanged at $1.60 to $1.70 per Mcfe for full-year 2016.
G&A expenses were $43.7 million, which is down $5 million in the first quarter, as a result of incurring additional legal expenses in the first quarter. In the second quarter we did incur a $1.8 million of severance expenses associated with the reorganization that occurred in April and the associates workforce reduction.
We have increased the midpoint of our guidance for G&A expenses by $15 million to a $170 million for full-year 2016, the increase reflects the un-anticipated legal expense in the first quarter and restructuring expense in the second quarter and the $5 million increase in non-cash compensation expense driven by the increase in our share price this year. We now expect non-cash compensation expense to be approximately $40 million of the $170 million for the year.
Capital expenditures on an accrual basis were $86 million for the quarter, down from the $157 million in the first quarter, as a results are dropping our operated rig count from nine rigs at the end of 2015, to three rigs at the end of the second quarter. In addition, we made $9 million of acquisitions, and deposited $30 million in extra account for the Permian acquisition.
Anticipation of closing of Permian acquisition, we have increased the midpoint of our guidance for 2016 capital spending for drilling and completion activities to $525 million, which is up $50 million from initial guidance, and Chuck will give more details in a minute.
With regard to the balance sheet, at the end of the quarter, total assets were $7.5 billion, shareholder equity was about $3.7 billion. Total debt was approximately $2.2 billion, all of which were our senior notes and we had $1,038,000 billion of cash on the balance sheet. In June, we sold 200 million shares of common stock and received net proceeds of approximately $413 million. We expect to use these proceeds to fund the portion of the Permian Basin acquisition. In addition, entered to the first we have a $177 million of senior notes that come to expecting this cash and the balance sheet fund that maturity. Finally, we have file our 2015 Federal tax return and we expect a refund of approximately $155 million later this year.
I will now turn the call over to Chuck.
Good morning, everyone. Since Richard’s already covered a summary of our second quarter operational and financial results, I will give you a quick update on our progress on our recently announce Permian Basin acquisition. I'll add some strategic context to that deal and then I will share with you some color on our asset level operational result and finish up by talking briefly about our plans for the remainder of 2016 and then we can move on to Q&A.
As you know on June 21, we announced an acquisition of approximately 9,400 acres in the Permian Basin of Texas. This transaction is a direct result of our ongoing strategy to reposition QEP to a more balanced production and reserves mix by bolting on high quality acreage adjacent to our, close proximity to our existing core oil assets.
A quick reminder of the deal highlights. First, we are acquiring Permian Basin crew properties in Martin County, Texas located about 10 miles east of our existing production operations in the heart of the Northern Midland Basin. The deal was structured a bit unusually, because there is a large number of potential sellers, there were about 113 in total.
So initially, we executed a purchase and sale agreement with a smaller group of initial sellers, that contain customary purchase price adjustments for things like title and environmental issues, but the PSA also contained a unique provision that the initial sellers had until July 13 to obtain joinders to the PSA from enough of the remaining orders, such as the total aggregate value that all of the sellers delivered exceeded 90% of the allocated purchase price of approximately $600 million.
As of July 13, we received joinders that when combined with the interest of the initial sellers that were signatories to the PSA of approximately $595 million of aggregate value, over 99% of the total interest that was potentially available for purchase.
This represents approximately 9,340 acres that were tendered for sale and from a total of 106 committed sellers with an average working interest of about 96% and an average royalty burden of about 23%. As a reminder, these numbers could still change, because there are still subject to the adjustment under customary provisions in the PSA for title and environmental issues, if we identify any such issues in due diligence.
Third, as you can see from the accompanying slides, the acreage is contiguous and it’s nearly a 100% operated by QEP. Approximately 98% of the acreage is held by production to the base of the Wolfcamp formation or deeper by 96 existing vertical wells. We have identified and placed value on four discrete horizontal targets, including the Middle Spraberry, the Spraberry Shale, the Wolfcamp A and Wolfcamp B horizons, and we think there are additional potential development opportunities in deeper and shallower horizons.
Our base case for valuation was based on 312 horizontal development locations with identified upside totaling at least 430 horizontal development locations in the four primary target horizons. And when we apply our anticipated risk schedule that represents at least six years of development drilling inventory.
The current net production from the required assets from the 96 vertical wells is about 1,400 barrels of equivalent per day, about 83% if which is crude oil. The acquired asset has net company estimated proved reserves of approximately 76 million barrels of oil equivalent with total net company estimated recoverable resources of 275 million barrels from the four primary zones with additional potential in shallower and deeper horizons.
And as Richard mentioned, we will fund the acquisition with the proceeds from our June 22, 2016 equity offering and from cash on hand. And we anticipate closing the transaction on or before the end of September 2016.
Now, let me put the acquisition into strategic context. As you guys know, since the creation of QEP as a public company in June 2010, we have been focus on growing crude oil as a percentage of both proved results and production in our asset portfolio and over the past several years we made tremendous progress toward this goal through a combination of targeted acquisitions and through the drilled in.
Back in 2010 crude oil represented just 8% of our total equivalent production and 10% of our year improved results. And as a result of the South Antelope property acquisition in 2012, our entry into the Permian Basin in early 2014 and combining this with organic production growth driven by our talented asset managers applying cutting edge drilling and completion techniques to these two world class assets. Crude oil represents 36% of total 2015 production and 32% of year-end improve reserves.
Some of you have asked about for more color around our ability to efficiently execute our drilling plan within the footprint of the same to be acquired acreage. Let me try to help you understand by putting these new asset footprint in the perspective it's roughly the same size as the currently productive portion of our Pinedale position, where some of you may recall under the BLM record of decision that allowed us to go to year around drilling and completion activities.
Our new well delivery operations or activities that any give time or constraint to a concentrated development area or what is referred to the CDA that is no more than six square miles or about 3,800 acres in size. As recently as 2012 we had six rigs drilling in Pinedale including three drilling rigs drilling on a single pad. And we have simultaneous completion flow back and production operations inside the Pinedale CDA.
Since 2004 we have performed with our incident simultaneous operations at Pinedale, which include both drilling completion and production activities on single pads. And we successfully exported this expertise that a lot of each which we developed to other new resource players in our portfolio, including both the Williston and Permian Basin assets.
For example on a Williston Basin throughout the analog what we have operated three rigs drilling on adjacent path we have had up to seven rigs in total on the asset, while we and offset operators simultaneously fractionally stimulated nearby wells of a small sub set of the acreage. And more recently as we have commenced our infill and deeper bench program we protected additional skills for drilling and completing wells inward those proximity to existing well boars.
In short we have the people the techniques the management systems and the expertise that make us highly confident in our ability to safely and efficiently execute our plan to development on the new acreage. So if you are referring to slides to that the company has released yesterday slide five through nine will give you more details on our 2016 Permian Basin acquisition.
Now let's review some operating highlights for the second quarter. Starting in the Permian Basin production translating for the average more than 17,300 barrels of oil equivalent per day and that was about 83% liquids. A daily record rate and the 4% increase from the first quarter and a 53% increase in the second quarter last year.
During the second quarter we complete in term sales six grossed operated horizontal wells following the Lower Spraberry shale and all with outstanding results. The six wells at an average 24 hours peak gross rate of 1,465 barrels of oil equivalent per day from an average lateral link of 7,280 feet and for those who you are comparing quarter-over-quarter results that's all shorter or lateral average lateral link and we reported last quarter.
Two of these wells were the first wells that we drilled in the new wine rack geometry that we described you earlier this year and we are quite encouraged by the early performance of those wells. We also continue to evaluate an exploratory well that we drilled on the new play concept in the Permian Basin we mentioned last quarter. This is outside of the footprint of our existing acreage and that well was turned to sales in the first quarter. We are still collecting and evaluating information on the well and this is still too early to give you a definitive thumbs up or thumbs down the results.
Current AFE gross drilled and completed well costs for Spraberry wells average $5 million with costs associated with facilities and artificial lift, adding about $700,000 about per well. We had one rig active in the Permian Basin at the end of the second quarter and we had an inventory of two QEP operated wells that were drilled but not yet completed or DUCs in the vernacular of the industry, and both of those wells were in the Spraberry shale and we had a 100% working interest in both of them.
With the closing of the 2016 Permian Basin acquisition anticipated occur by the end of September, we plan to add two additional rigs in the Permian during the fourth quarter. The rigs may start on our existing acreage and migrate to the acquisition acreage or they may start directly on a new acreage depending on both the timing of rig arrival and the timing of completion of land work that form drilling units on the new acreage. This resulted in an increase in the midpoint of our forecasted 2016 development drilling capital as Richard has already mentioned, of approximately $50 million.
Slides 11 through 14 give you more details on our Permian Basin assets. Williston Basin net production during the quarter averaged 57,900 barrels of oil equivalent a day, an 8% increase over first quarter 2016 and 10% improvements over the second quarter of last year. During the second quarter, we drilled nine horizontal wells targeting both the Middle Bakken in Three Forks Formation. We completed and turned to sales one gross operated well during the quarter and that well is on South Antelope and we had a 100% working interest in it.
A second factor that is, we continue to be please with the performance of the high-density pilot projects in second and third bench delineation wells that we drilled on our acreage. We provided the cumulative production graph on both of these slides that the company released yesterday, so you can see the performance of both the infill wells and the deeper bench wells.
The first group of five infill pilot wells have averaged over 300,000 barrels of oil equivalent per day of cumulative production, that’s a downtime adjusted cumulative production and about a year on line. And the second group of five infill wells which have been on line for 180 days, about half a year, have averaged cumulative production of over 216,000 barrels of oil equivalent per well.
In the Three Forks, we now have 12 second bench wells and one third bench well on production and they all continue to deliver outstanding cumulative results. Our oldest second bench well, which at the time of the second quarter, have been on production about a year has produced over 339,000 barrels of oil equivalent. While our sold third bench well, which has been on production for 180 days has cumed 243,000 barrels of oil equivalent.
We had one operated rig running in the Williston Basin at the end of the second quarter and we plan to continue running one rig throughout the end of this year. At the end of the quarter, we had a total of 28 gross QEP-operated DUCs, 25 of which were on South Antelope and three at Ft. Berthold that we are standing waiting on completion and those wells averaged an 88% working interest. We also have interest in 25 gross DUCs that are operated by others with an average working interest of 6%.
As we mentioned in our release, yesterday, there’s an ongoing commercial dispute with a midstream company that purchases, gathers and processes associated gas from our South Antelope oil wells that negatively impacted completion activities and production volumes during the quarter. The industry and service providers are willing to connect recently drill wells on our South Antelope acreage to its system unless we pay increase fees. If the dispute continues it may impact the pace at which we are able to complete additional drilling uncompleted wells during the third quarter 2016 at South Antelope.
We think we have strong arguments in our favor in this dispute but if we lose we get incur roughly $2.5 million for the amount of additional transportation expenses at South Antelope. At this juncture we think our guidance accurately reflects the risk, their implicated by these delays and less the parties result these to speed epically their matter will be decided in binding arbitration with worldwide to conclude in the fourth quarter of 2016.
Since this is as a legal discreet I would prefer not to providing the additional comment on the spending, proceeding beyond the information that's contained in the release. Slide 15 to 20 have additional details on our Williston Basin assets. Tuning to Pinedale in their production average 251 million cubic feet of gas equivalent per day during the second quarter.
The Pinedale production as you all know always declines sequentially from the fourth quarter levels due to suspension of well completion activities during the quarters much as a winner. But due to lower gas prices, we didn’t completing the wells at Pinedale in the first quarter of this year, we only completed four wells with an average working assets of 85% late in the second quarter.
The current drilled and completed well cost for queuing the operated wells averaged 2.7 million with facilities and fonder lift adding an additional 200,000 per well. At the end of the quarter, we had one cubic feet operated rig growing at Pinedale, which we plan to operate through year-end. At an inventory of 32 grows cubic feet operated docks with an average working interest of 53%. Slide 21 and 22 provides additional details on our Pinedale property.
So, in conclusion we continue to make good progress on improving the economics on our existing assets by increasing well production performance with enhanced completion designs coupled with the relentless focus on driving down total completed well cost. We continue to organically grow our inventory or future development locations across our existing acreage through identity inflow development in proving up deeper three fork bonzes in the Williston and continues the special drilling excellence, great work potential in the Permian.
Additionally we are getting if organic inventory growth we did captured in the well longer path at the closing in Permian acquisition that we believe represents a tremendous opportunity to leverage out for our existing Permian operations. Were anxious to start work on the new asset to drive profitable crude oil production and reserve growth while substantially increasing our future development drilling inventory.
As we developed the new asset set it's not only drive crude oil and EBITDA growth but also drive EBITDA and margin expansion. We are excited about the addition in this new high quality crude oil assets on our portfolio as we continue to execute on our strategy to reposition QEP to one of our balanced mixed of crude oil and liquids reach gas production and reserves.
With that Barak, we can open the lines for question.
Thank you. [Operator Instructions] Our first question today comes from David Heikkinen of Heikkinen Energy Advisors.
Really, just don't want to talk about the dispute in - but did want to understand as you think about getting back to work on South Antelope and how quickly and how do you think about hooking up and completing those wells when its resolved.
David, thank you for respecting our desire not to talk about details. Look our frac crew doing plug and perf wells can deliver roughly six wells a month. So a couple frac crews we can work though that stuck inventory pretty quickly. It puts us in a great position for a momentum in the 2017 obviously.
Okay and then, I know this is thinking about your guidance for the second half of the year. do you have any thoughts on exit rates for the year post acquisition?
Well the acquisition only contributes about 1,800 barrels a day or so of production. We will put two rigs to work and as I mentioned in my prepared remarks, we are going to be sitting, put those rigs first likely on our existing acreage as we do the drilling unit formation and then move the rigs over and start to work on a new acreage.
But it’s really a minimal, roughly, I would guess a few, maybe a 100,000 barrels of incremental production in 2016 from those two rigs is really going to be sitting on pads and drilling and not really contributing much to the 2016 production volumes.
And just to refresher your memory, we talked about 2 million barrels equivalent roughly, I’m sorry just 2 million barrels of crude oil production, incremental production from the newly acquired asset in 2017.
And obviously, we’ll update that as we get the asset in hand, as always, a bit of timing around, just land work that has to be done in front of the rigs before we are fully confident on the ramp-up there. But we are pretty confident that we can at least deliver 2 million barrels of incremental production from the new asset.
And so if you think about this corporate wide, I was meaning, just the corporate exit rate, not just on the asset?
We haven’t given exit rates and some of that's going to depend obviously on timing around completion of wells in North Dakota.
Yes. It's worth a try. And then, you address the thoughts on 99% of the assets that have signed joinders. The only other question I guess the wildcat well, just tracking, it looks like is in Winkler County, is that something you'd update in the next quarter or they take more time for production results??
Without going into the gory details, the well is performing, is not performing to our expectations and to the expectations are created by the core data and wire line data we have, as well as analog data from other similar plays and so we think that there is some potential, precipitant in the well that was caused by a mixture of the frac fluid with some materials in the rock that may be impacting the performance. The team is evaluating, either re-stimulating the well or potentially drilling another well and we are just not ready yet to talk about the details until we make up our mind on the next step on the evaluation of the asset, but stay tuned.
Next question comes from Kevin Smith of Raymond James. Please go ahead.
Hello, good morning gentlemen and congrats on the solid quarter.
Chuck, appreciate your prepared remarks on this, but would you mind discuss a little bit more about the right well spacing in the Spraberry Shale. I guess, specifically the differences in spacing you displayed in slides 9 and 14, and then as you look at things?
Well, ultimately wells facing in the Sprayberry shale or any of these unconventional reservoirs is driven by an oil in place calculation and that number is derive from a combination of core data and wire line data. So, the difference that you have observed in the wells facing this between the existing asset and the newly acquired asset is been driven by a change in the oil and place calculation and therefore the ability to put additional well boars on the target acreage.
And again these are initially valuations based on no horizontal wells been drilled in the acquired acreage so that number could change as we get additional encouragement from production performance on the newly acquired acreage.
The other thing I would point out to you is, when we talked about the 430 locations and we talk about the number of the 16 development locations in the Sprayberry shale that's in all categories of risk reserve so that includes probably possible locations that are not necessarily valued fully in the initial acquisition model that we carry.
So ultimately what drives it again just to summarize this oil in place and then dividing that oil in place against the number of take points or wells drilled into the reservoir and testing that against the reasonable recovery factor for the rock properties that we observe in each of these reservoirs.
I guess maybe to kind of follow up on that, is the process that you are thinking about going forward still the 750 in the Chevron sort of pattern in the newly acquired stuff?
Well the 750 is in the previously acquired so for existing asset and we call that legacy asset. We are going to name it county line in order to differentiate it between the newly acquired asset but the chevron pattern is driven by the baffles that we observed in the wire line logged data from the existing vertical wells and then newly acquired assets. So yes it's a wine rack or chevron pattern so that we are not putting existing or that putting horizontal well boars directly on top of each other so that would minimize or risk some vertical fractures propagating into and overlying or underlying well boar.
Got you and then lastly, and I'll jump back in queue, is there any oil price sensitivity to your rig increase over the next six months or do you feel like you are pretty locked in there?
Well we have been we would be looking at forward price of roughly $50 in 2017 and risk management group has been aggressively hedging into that price and at $50 we think that the economics are supported the economic support by adding the rigs that go into 2017.
Thank you very much.
The next question is from Neal Dingmann of SunTrust. Please go ahead.
Good morning guys. I should say, again, nice quarter. Just on a production question, certainly overall production I think came in better than I was expecting even at despite, I think, at the Bakken, maybe just slightly lower. So, I’m just, I guess my question is, how you all think about just the typical PDP decline, when you look at now the Williston versus the Permian, including the new and then the Pinedale as well?
Overall, corporate PDP decline is in the high-20s, 27% or so. And individual asset decline, yes, it varies, Neal, depending on the level of activity immediately before you ask the questions. So, I think we surprised a lot of people in the second quarter with strong production results.
Part of that is due to for instance in the Williston Basin, the completion of 17 wells in the first quarter, which really, and a lot of those wells were toward the back end of the quarter, which drove strong second quarter production performance, despite the fact that we only completed one well in the second quarter in the Williston Basin.
So, the asset level production decline goes up and down, initial production goes up and down depending on how many new wells you had, obviously we had 17 new wells. You steepen that initial decline for a while. Overall, one of the things that we have observed is on an individual well basis, the decline, the initial one-year decline rates are lower in the Permian Basin than they are in the Williston Basin and is because of the difference in permeability.
The wells in the Williston Basin are drilled in reservoirs which are frankly low quality conventional, extremely low quality conventional reservoirs as opposed to the wells we drill in the Permian, which are true shales in many instances instead of being crappy conventional reservoirs.
Got it, got it. And then, Chuck, you nearly did say, obviously not to talk about the midstream issue, but just wondering could you just maybe talk about how you and Richard think about in relation that to your 2016 guidance. I know think I can ask about sort of the exit rate around that. But just kind of curious how you think about that, given you have put out sort of the average guidance for the year.
We have not been in the habit and I don’t think this is the right quarter to start getting into the habit of giving exit rate numbers and exit rate numbers are again highly dependent on timing, even within the fourth quarter on when we get wells online. So if we have a bunch of wells kind of herded up toward the last month of the quarter, we are going to have a very high exit rate going into year end and it could be misleading as you think about first quarter and that’s always a struggle.
But what I’ll say about the way we came up with the guidance is, first of all, I would observe that we have raised the midpoint, so we pulled up the bottom end of the guidance and the factors impacting completion activity in North Dakota are properly considered, we believe, in the guidance that we gave yesterday.
Got it, got it. One last one, if I could, obviously knew that new area that you bought had just a tremendous amount of potential zones as you indicated in your prepared remarks. How do you think about going in, I mean do you go in just with kind of a stack pattern, the wine rack pattern right away or do you just go after sort of the B and the C and just wondering again there are so many opportunities with zones there? Initially, how do you attack that?
The good news is we have 96 control points on the acreage and they are spread pretty evenly across that acreage block. We haven’t put the vertical wells on the map but they given excellent control for the sub service and we think we can translate the wire line data and core data that we have collected 10 miles to the west.
And then looking at the performance that will offset operators wells that have been drilled horizontal wells have been drilled to confidently step into the new acreage and basically start the development and our plan is to start development on a drill out that will mimic the cartoon that's included in the slide deck.
Very good, thanks for the details Chuck.
Then next question comes from Kashy Harrison of Simmons Piper Jaffray. Please go ahead.
So, I'm trying to get a sense of just goalposts for what a 2017 could look like and combining the 2 million barrel of oil guidance you mentioned earlier on the newly acquired Martin County acreage and the $250 million CapEx guidance that's been mentioned on other conference calls.
And the fact that this year, you are kind of keeping oil production rather up at around $500 million and so, just adding all those things together and understanding that it could be a little bit early, but just for modeling purposes should we be thinking about 10%-ish production growth in 2017 kind of assuming $750 million of CapEx?
Well first of all, let me start by caveating this by that we are not giving 2017 guidance on this call. We have given comp owners the guidance in conjunction with the recently announce acquisition. But I think a reasonable assumption around oil volume growth is in the high single digits low double digits at this point and part of that depends on the capital program and also it depends on timing on when we are able to stand up all the rigs on the new asset and get going.
But that's a reasonable expectation so the 10% that's what you said and as we get the asset into the portfolio gets land work done and drilling activity. Obviously comp and slower oil in 2017 will go up, we might be able to give you little more color on the third quarter call but certainly by yearend we will have a much better handle on 2017.
Alright, thanks for that. I appreciate it. And historically, you thought about the Haynesville as sort of an option on improving gas prices and so, the cal 2017 strip is hovering around $3.10, $3.20 in them. And so how does that asset currently compete for capital in your portfolio?
I'm trying to be slipping here I guess the answer as it depends and part of it depends on what crude oil prices are and where they has in the 2017. Certainly we watched with interest the well reserves from smart set operators where we have done participate in some wells at fairly low working and for ourselves that operated wells.
Well three things are driving improve economics in the Haynesville the first is just overall lower well cost with the industries that captured across all of the place. Two, most operator are now drilling longer laterals where historically we drill the industry 4,500 to 4,800 foot laterals. Today most operators are drilling 7,500 foot laterals.
And then third, and probably the most important is most operators are now pumping on average 3,000 pounds a foot proppants as opposed to, what do we pump Jim, maybe 1,300 pounds a foot or even less on average, when we were actively developing the asset.
And it’s clear from watching the well performance of the new wells, that the bigger fracs make a huge difference in the performance of the wells that are currently being drilled in the plays. So economics are pretty interesting and it’s a great gas option to have in our portfolio. So we are continuing to monitor results; too early to give 2017 view on how much, if any, capital we allocate to the asset, but stay tuned.
And then just last one from me. Can you quantify the production impact from switching to plug and perf completions from sliding sleeve completions? I think in the earnings release, you had mentioned that the economics that had improved from switching?
A couple of things. One, there is arguably a slight increase in initial performance of the wells, but more importantly, we think the estimated ultimate recovery on these wells because of the improved stimulation efficiencies, more stimulated rock volume more than offsets the incremental couple of $100,000, $200,000 roughly of increased costs.
So, it used to be when we first started comparing and contrasting sliding sleeve completions versus plug and perf completions, we were talking about over, really over $1 million of incremental costs for the same number of stages and based on the same proppant loading. And so, it’s come down to less than a fifth of that cost now, and the economics associated with the incremental recovery more than cover the $200,000. That makes sense.
Alright, fair enough. Well thanks for taking my questions and a good quarter guys.
The next question comes from Gabe Daoud of JP Morgan. Please go ahead.
Hey good morning, guys. Most of my questions have been answered. So, I guess I’ll ask the portfolio optimization question. You talked about the alien zone that could potentially compete for capital, but how do you think about asset sales or even potential future acquisitions of oil assets? How you think about potentially divesting maybe something like the Pinedale?
Good morning. That’s a great question, and look, I think if you look at the behavior of this management team over the past several years, we have done a lot of portfolio optimization, we sold a lot of non-core assets, we sold out of Powder River Basin in Wyoming, we sold assets across the Mid-Continent.
Basically we are now out of the Mid-Continent, sold [indiscernible] and we sold SCOOP/STACK, we sold Granite Wash. And we continually look at the value of the assets in our portfolio and the drill out of those assets versus the potential sales price of the assets or whether or not they be more valuable in other people’s hands, you could accelerate the present value beyond what we see and what is reflected in our stock price.
So as far as immediate plans to sell something, we don’t have any but we continue to evaluate additional both on opportunities and our two core oil plays and a monetization of one of our assets that is less core to us as certainly one way to finance such an acquisition.
Then maybe just one more follow-up from me just thinking about rig additions, obviously, the focus is on the Martin County acreage. How do you think about future rig additions between the State Line area or your legacy Permian versus like say South Antelope, how generally, I guess how're you thinking about rig additions on the legacy Permian position?
Only correct to record this. County lines not state line and if I say it’s right I may spoke. So I look at it as at personal geologically and from a reserve potential I think the two assets are interchangeable and so from an operational perspective you can very well see just like I described in our prepared remarks the rigs hoping back and forth between the two assets as we jump from pad to pad and we drive a completion activity across those asset.
So we are adding two rigs to the Permian and from a modeling perspective I think you did the same production response regardless of whether those rigs are operating on our legacy county line acreage or in the newly acquired acreage and as we guided in our acquisition announcement up to five rigs running on the newly acquired assets it maybe a time to all five of them were running there.
There maybe three on the newly acquired asset and two on the straight line asset or there may be times when all five rigs are running on this and state line assets. So because of the very similar rock properties and very similar expected results, so I think this adds optionality from an operational perspective to our portfolio, as well as it should be pretty simple for you to mob.
And I will say again we are not concerned about operating five rigs on the new asset, we think that's a very easy to do and we can this has run five rigs and simultaneously we completed and produced well as we sort of go about developing this new asset which because of the relatively small number of verticals wells it allows us to basically - and no continues meaningful continues drilling obligations or HTC issues. We can go about the full development of this asset in a very orderly and logical fashion and I have to jump around a lot.
Okay, got you. Thanks Chuck that's helpful.
The next question is from David Tameron of Wells Fargo. Please go ahead.
Chuck, when you talked about 2017, how should, I know you gave some guidance around production, but how should we think about philosophically, are you within EBITDA, within cash flow, presumably with the higher price, do you feel comfortable spending, where do you sit on all that?
Finally, of course and that Richard can answer.
I think the plan that we contemplated with the Permian Basin acquisition we talked about a quarter billion dollars in capital spending in 2017 and again what if you know what the what price forecast is we get it contemplated that would be about a 150 million of over spend on the corporate basis next year we don’t have in debt maturities next year.
So that is interest carry plus overspend versus the EBITDA and we will have plenty of cash $350 million and $375 million of cash at the end of this year rolling into next year to finance that overspend. But that’s kind of looks like, again before we have our hands on that asset.
Okay. And Richard, since you’re already speaking it. Can you do anything on the, as far as off the 1031, what would be the timing on that, if you could pull it off for an exchange?
So, when you acquired the asset first versus selling an asset first, it’s a reverse 1031. So, you actually have to warehouse that acquired asset off your balance sheet in some third-party vehicle. And we are not really contemplating that.
So it would be a 45 day to identify and 180 days to close. That’s not saying, if we don’t have an additional transaction that we are looking at this year, then we can do that. But right now, we are not planning on doing any kind of reverse exchange on the Permian acquisition.
That’s helpful. And then Chuck, I’m going back to the Bakken. In the release, you have some, you have the fume rates, I guess, somewhat the density of the infill wells have done and they look like versus the numbers you put on the first quarter, they have actually gone up on a per day basis and I realize like in some cases once 270 days versus 360 days.
Yes. You caught us, we went from, we realized we were reporting two stream data before and we changed the three stream data to be comparable with what other operators are reporting. So that’s the difference, David.
Okay and that's the foot note in the…
Okay. And then one last big picture question. I guess, back to Richard since he is - I'm going to [indiscernible] him from couple years ago. I remember coming to your office one time, Richard, you talked about growing EBITDA per share and just tell me your per share metrics, that was maybe contributed to the stock price now working, call that 2012 timeframe, 2013 timeframe, 2014 timeframe. How do you feel about kind of that type of metric going forward and position now with these assets that you can drive or how should we think about that?
David, that’s one thing we absolutely look at and if you could just take commodity prices out of the equation, one of the things that transition to oil assets does for us is it actually expands or EBITDA margin, both on our production basis, on a per share basis. If you look at where we are today and you assume $600 million of EBITDA for the year, we are $2.50 of EBITDA per share and absolutely expect that. Even if you take the price move in and out of the equation to expand next year as we develop the new Permian asset continue to expand, what we do on our oil properties and why we are directing capital to the oil side versus the gas side, it’s actually margin expansion.
Okay. That’s helpful. thanks and nice quarter.
The next question comes from Brian Corales of Howard Weil. Please go ahead.
Good morning, guys. Most of my have been asked, but if we look at the - I guess, whole issues in the Bakken, but have you ever thought about bringing that rig to the reservation?
As a matter of fact yes that's maybe where it is now.
Fair enough. Alright there you go. That's all from me. Thanks.
The next question is from Josh Silverstein of Deutsche Bank. Please go ahead.
Hi good morning, thanks guys. I guess I can stay there as well, I mean the Permian seems to be the growth driver going forward. Are you thinking about raining in spending in the Williston Basin next year, or are you just looking to try to keep South Antelope or the whole basin flat as you kind of direct more capital towards the Permian?
Josh good morning. Look I think there is still a tremendous opportunity in the Williston Basin on both South Antelope from the infill program and from the deeper benches. And how you really have not done there so stat of the yard plug in curve high traffic loading completions on our both vertical acreage to the east and so we think there is a lot of upside potential to help to drive feature growth there as well so I would not say that were parking or putting the Williston Basin asset in the neutral far from it.
We think there is still a tremendous amount of running that we don’t have ask to. And as we go into 2017 obviously we are excited about the Permian we are excited about the well results we are giving from the Spraberry shale on that County Line asset we are very excited about the newly that seem to be acquired new asset.
But I don’t want you to think that we are walking away from or that were I can start the Williston Basin assets is going to be an important part of our future growth. And as we have talked about previous quarters we have been quietly bolting on additional interest in wells that we already are drilling and completing and we are looking for additional bolt on opportunities there as well.
That's helpful, think about that for next year. And I guess, since most questions have been asked, when you put it on to your Pinedale side, you just talk about the horizontal opportunity there, cost, potential well size, anything that you guys are thinking about for that.
So, as the Josh the best wells at Pinedale are along the crest, the highest IP, highest EUR wells and actually the area we are drilling in at Pinedale now with our normal vertical well development program is the home of the biggest highest EUR wells in the entire field. In fact there is several wells in the area we are drilling that have already produced over 12 to 15 biz of gap there some 20 Bcf wells in the areas called Stuart Point.
Around them around the edges of the field we have a red line drawn on our map and we say that's the limited on the field it's really the economic limit for drilling vertical wells there is no definitive gas water contact at Pinedale we just go down on the franks of the unique line. The rocks get deeper they hit the rock properties deteriorate and water saturations increase but the wells will still produce gas and at $5 or $6 gas that gas is economic at $2.50 or $3 gas it marginal.
But based on what we have learned from the drilling horizontal wells in the Williston Basin as well as watching the couple of wells that were drilled over in the Jonah Field immediately to the southwest of us. We think that the same horizontal drilling success that we reported in earlier quarters in the Uinta Basin can be translated to the flanks of the Pinedale Anticline and that could add substantially to the inventory of future development there and also additional reserves and productions from an asset that’s admittedly maturing.
And if you look at the remaining future development just from the vertical wells. Well costs, it depends on how, on what part of the interval you target because there are shallower sands, you remember that the pay section of Pinedale starts at about 9,000 feet and goes down to over 14,000 feet. So shallower horizontal wells - we haven’t drilled one yet, so I can’t give you a real accurate number, but $6 million to $7 million and maybe another million or so for the deeper part of the section.
And we don’t see why it would not work at Pinedale since we have had good success doing it in the Uinta Basin and just a reminder, it's the same rock. The Mesa Verde formation is very similar in geology on both sides of the Uinta Mountain, so in Wyoming, it looks very similar on logs and from core as it does down in Utah and in Uinta Basin.
And one other thing I would note, if you look at the Pinedale slide in the slide deck. You will see that if you’ve been following the company for a long time that the footprint has changed and one of the things that we have done is we have been able to pick up some additional acreage around the flanks of the Pinedale Anticline, which allows us to drill longer horizontal wells out into the flank areas, especially on the east side. So that’s a change that you will note, if you look at the, if you compare the yellow on the map to previous quarters. Josh, are you there? Barak, are you there?
Yes, sir. Mr. Silverstein your line is still open. Have you finished your questions?
I’m okay. Thank you.
Thank you, Josh.
Ladies and gentlemen, we have reached the end of the question-and-answer session. I would like to turn the call back over to Chuck Stanley, President and CEO for closing remarks.
Well in conclusion, I would like to, I thank you all for dialing in for today’s call. We appreciate your interest in QEP and we look forward to seeing you as Richard and I are on the road attending a number of sell-side conferences over the next month or so. Have a good day.
This concludes today’s conference. Thank you for participation. You may now disconnect your lines.
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